OGJ Newsletter

Nov. 4, 2013
International news for oil and gas professionals

GENERAL INTERESTQuick Takes

API to lawmakers: Voters oppose new energy taxes

American Petroleum Institute lobbyists plan to remind members of the 113th Congress considering possible federal budget reforms in 2013's final weeks that their constituents don't support new energy taxes, said Stephen Comstock, API tax and accounting policy director.

They specifically plan to cite findings of a recent Harris Interactive telephone survey API commissioned of 1,001 registered voters nationwide that found 56% oppose federal tax code changes that could reduce energy investment and decrease energy production, Comstock said in an Oct. 29 teleconference.

"The players continue to change on the budget and other committees," he said. "It's another opportunity for us to engage with a broader group and get their impressions and feedback. Having this kind of polling provides immediate feedback of how their constituents feel."

Comstock noted that a study this summer by Wood Mackenzie found that repealing the federal exemption for intangible drilling costs (IDC) would result in fewer wells drilled, fewer Americans employed, and less energy produced domestically.

If the IDC deduction is repealed, Comstock said, 190,000 Americans would be unemployed next year, "growing to 265,000 jobs lost over a decade, according to the study." He said, "With nearly 10,000 fewer wells drilled and $407 billion in decreased investment, domestic oil and natural gas production would fall 14% below current expectations after 10 years."

Oil and gas industry concerns over possibly punitive tax proposals may not be new, but some federal lawmakers may only recently have become members of key committees and aren't acquainted with the issues yet, he indicated.

"I think we've been fairly steady in how we engage members," Comstock said. "We've maintained a steady meeting schedule and tried to highlight economic issues as we see them, particularly what the oil and gas industry is doing in the context of the broader economy. From our perspective, I think we've kept up a pretty strong drumbeat."

Survey shows safety as top industry concern

Natural gas producers told pollsters in a survey earlier this year that safety was their top concern followed by environmental regulation and economic growth, said Black & Veatch's 2013 Natural Gas Industry report covering North America.

Midstream representatives also listed safety as their top issue followed by economic growth second and environmental regulation third, the report showed. Safety issues cited by industry included integrity management programs, cyber security, and environmental issues.

Both upstream and midstream survey participants listed capital access and cost as their fourth concern followed by rate and regulatory issues.

Peter Abt, B&V managing director of oil and gas strategy practice, said the general consensus was that more pipeline capacity is needed. "How this capacity is financed—and who pays for it—is the area of disconnect," Abt said. "Without pipeline investment, the natural gas industry's growth will slow, and consumers could see dramatic price swings."

Survey participants said they believe gas prices will reach $4.50-5.99/MMbtu by 2020, noting that industry is reliant on economic growth.

During July and August, B&V gathered 336 responses from producers, pipelines, and utilities. More than 95% of the gas executives said they were optimistic or very optimistic regarding the outlook towards future industry growth.

Some 85% expect gas-generated electricity will drive demand growth. Other demand drivers are expected to be LNG exports, transportation, petrochemicals, and manufacturing.

Alberta bill creates environmental monitor

A bill introduced Oct. 28 in the Legislative Assembly of Alberta would create what sponsors call "an arm's-length agency" to operate an environmental monitoring program working initially in the oil sands.

Diana McQueen, minister of environmental and sustainable resource development, introduced the bill, which will create the Alberta Environmental Monitoring, Evaluation, and Reporting Agency.

The agency will be responsible for work now done under a joint program of the governments of Canada and Alberta for environmental monitoring of oil sands development. Its work later will expand to encompass province-wide environmental monitoring, evaluation, and reporting as land-use plans are implemented.

New York starts strategic gasoline reserve

The state government of New York has begun a pilot program to store gasoline for use in emergencies.

A response to Hurricane Sandy, which slammed the US East Coast a year ago, the $10 million program, called Fuel NY, will store 3 million gal of gasoline on Long Island.

The state has a contract to use storage owned by Northville Industries.

The government called Fuel NY the first state-based strategic gasoline reserve in the US.

The pilot is designed to provide emergency fuel supplies to motorists and first responders on Long Island but could supply other areas of the state.

"In all emergency scenarios, the reserve will only be used as a supplement to market deliveries in order to maintain adequate levels of fuels during an emergency recovery," the state said.

Exploration & DevelopmentQuick Takes

Petrobras drills 26-km stepout to Santos presalt find

A group led by Petroleo Brasileiro SA has proved an extension of the 2008 Jupiter presalt oil and gas-condensate discovery in the deepwater Santos basin offshore Brazil, from which production is expected to begin in 2019.

The 3-BRSA-1183-JRS (3-RJS-713) extension well, 26 km northeast of the discovery well on the BM-S-24 block, proved a 160-m gross hydrocarbon column topped at 5,322 m in rocks with good porosity and permeability.

The well identified a 100-m gross oil column with a gas cap and condensate. The gas contains an undisclosed percentage of carbon dioxide.

Analysis of samples from the extension well, known informally as Bracuhy, indicated the fluids to be the same as those encountered in the 1-RJS-652A Jupiter discovery well (OGJ Online, Jan. 29, 2008).

The extension well went to 5,765 m in 2,251 m of water 267 km south of Rio de Janeiro. The well is the third drilled in the Jupiter area.

A formation test is scheduled for 2014 in the oil-bearing zone in order to assess the characteristics and productivity of the reservoirs.

The group will proceed under the evaluation plan approved by Brazil's National Petroleum, Natural Gas and Biofuels Agency that calls for the drilling of an appraisal well and one formation test in 2014.

BM-S-24 block interests are Petrobras 80% and Galp Energia through its Petrogal Brasil subsidiary 20%.

Galp Energia noted that it also holds stakes in Santos presalt blocks BM-S-11 (10%), BM-S-8 (14%), and BM-S-21 (20%). It said the blocks hold "high exploratory potential."

DNO International has oil strike in Masila basin

A group led by DNO International ASA, Oslo, has tested 36° gravity oil at a rate of 5,900 b/d at the Salsala-1`discovery well on Block 32 in the Masila basin of east-central Yemen.

The company attained the 5,900 b/d initial rate before choking flow to 3,400 b/d due to limited tank space. The flow came from a 32-m perforated interval in the Jurassic Shuqra formation. Total depth of the directional well is 4,147 m. Cost to drill, complete, and test the well was $10 million.

Block 32 contains two fields, Godah and Tasour, that are averaging 2,500 b/d of oil.

DNO International will place the well on extended production test and plans to spud an appraisal well in early 2014 as part of a fast-track development.

Block 32 interests are DNO International 38.95%, Ansan Wikfs 42.93%, TransGlobe Energy Corp. 13.12%, and Yemen Oil & Gas Corp. 5%.

DNO International noted that it holds interests in five other blocks in Yemen, two of which are in production, one under development, and two in the exploration phase. Year-to-date, the company's working interest production in Yemen has averaged slightly above 4,000 b/d.

OMV sees oil shows in two reservoirs at Barents well

The OMV AG-operated Wisting Alternative well 7324/7-1S on PL537 in the Barents Sea offshore Norway has found oil shows in two poor quality reservoirs but has "provided important information about the regional geology," said partner Tullow Oil PLC.

OMV used the Leiv Eiriksson semisubmersible to drill Wisting Alternative to 2,452 m in 413 m of water 315 km north of Hammerfest.

The well was not appraising the 2013 major light oil discovery at Wisting Central 5 km southeast on a separate structure, but it encountered oil shows in the deeper targeted Kobbe and Snadd formations (OGJ Online, Sept. 6, 2013).

Extensive data acquisition and sampling has been carried out, and the well will be plugged and abandoned. The group will continue evaluating the Wisting Central discovery and understanding the regional geology.

Interests in PL537 are OMV (Norge) 25%, Tullow, Idemitsu, and Petoro 20% each, and Statoil 15%.

Angus McCoss, Tullow exploration director, said, "Wisting Alternative was a high risk wildcat well which has provided important information about the regional geology in the Barents Sea.

"The material Wisting Central oil field, discovered in the same license in September this year, will now be prioritized for appraisal in 2014 alongside our significant program of high impact wells that includes the operated Mantra well which is due to spud in November."

Drilling & ProductionQuick Takes

Statoil releases 'Snorre 2040' development concept

Norway's Statoil ASA has recommended the construction of a new drilling and processing platform for extracting the remaining reserves from Snorre field in the North Sea.

Together with Petoro and the other license partners, Statoil has worked to find a solution for extending the life of the field to 2040.

An evaluation of the "Snorre 2040" project has been carried out with examination of two development concepts: a subsea development with continued use of the Snorre A and B platforms or a development with a new platform tied in to Snorre A and B.

"The platform solution is the best alternative for maximizing production and creating the greatest possible value," said Oystein Michelsen, Statoil executive vice-president for the Norwegian shelf.

"Snorre 2040 is an important improved oil recovery project and supports our ambition of achieving an average oil recovery rate of 60% from our fields on the Norwegian shelf," Michelsen said.

Snorre field reserves are currently estimated at 1.55 billion bbl of oil. The original estimate when the plan for development and operation (PDO) was submitted in 1989 was about 760 million bbl of oil.

"An important contribution to the increase in recoverable reserves came with the decision to install a second platform, Snorre B, on the northern part of the field, and to start reinjection of produced gas from the mid-1990s," Statoil said.

Currently, the estimated recovery rate from Snorre is 47%, but the field "has an ambition of implementing additional IOR measures that will enable the field to increase the recovery rate to 55%," the company said.

Michelsen noted, "The change in the petroleum tax rules that was adopted in May also undermines the financial conditions of Snorre 2040, which means that we have to spend more time on maturing the project."

The final development concept decision is slated for first-quarter 2015.

A new drilling and processing platform also will facilitate tie-in of other discoveries in the area, the company said, adding that these are resources that might otherwise have ended up being not profitable to recover.

Snorre license parters are Statoil 33.27556%, Petoro 30%, ExxonMobil E&P Norway 17.44596%, Idemitsu Petroleum Norge 9.6%, RWE Dea Norge 8.57108%, and Core Energy 1.1074%.

Group tests remote methane-sensing methods

An industry-government program will publish "over the coming months" results of experiments on remote methane-sensing technology with application in oil and gas production, reports the Los Alamos National Laboratory (LANL).

The program aims to provide ways accurately to measure unintended releases of methane, a greenhouse gas, from human activity.

The group has tested ground and airborne sensing of controlled methane releases at the US Department of Energy's Rocky Mountain Oil Testing Center north of Casper, Wyo. In addition to DOE and LANL, its members are Chevron Corp. and NASA's Jet Propulsion Laboratory (JPL).

Chevron and LANL have collaborated on sensor technology development since 2001. The oil company entered a collaboration agreement with NASA in July 2011.

In June, the group tested airborne sensing of methane released at controlled rates and monitored downwind by a 45-ft tower at each release site. The tests used three aircraft and a "small, unmanned aerial system." The JPL deployed three airborne sensors, called Next Generation Airborne Visible and Infrared Imaging Spectrometer, Hyperspectral Thermal Emission Spectrometer, and an instrument suite called CARVE.

"The project is pioneering the development of ultrasensitive methane sensing technology to fill current gaps in quantifying fugitive leaks from petroleum extraction," said Manvendra Dubey of LANL.

Petrobras to charter another FPSO for Santos basin

Guara BV, an affiliate of Petroleo Brasileiro SA (Petrobras), has signed a letter of intent to charter a floating production, storage, and offloading vessel for use on Block BM-S-9 in the Santos basin offshore Brazil.

The FPSO will be provided and operated by Modec Inc. and Schahin Petroleo e Gas SA for the BM-S-9 consortium for a 20-year period. It will be delivered in June 2016—2 months before production is expected to begin.

The consortium is planning to connect at least 8 wells, 4 as producing wells and 4 for injection, to the vessel from the presalt layer in the Carioca area. The platform will have a processing capacity of as much as 100,000 b/d of oil and 5 million cu m/day of natural gas.

The BM-S-9 consortium is comprised of operator Petrobas with 45% interest and partners BG E&P Brasil Ltda. 30% and Repsol Sinopec Brasil SA 25% (OGJ, May 28, 2001, p. 45).

Ruby field gas flow starts offshore Indonesia

Mubadala Petroleum, Abu Dhabi, reported the start of production from Ruby natural gas field offshore East Kalimantan, Indonesia.

Mubadala didn't report a production rate. SKK Migas, which manages the Sebuku production sharing contract for the Indonesian government, earlier this year said the field would flow at a peak rate of 100 MMscfd for 4 years and produce 214 bcf over 10 years.

The field, in 60 m of water in the Makassar Strait, produces from four wells completed in the Oligocene Berai formation. Facilities include a six-slot tripod wellhead platform bridge-linked to a processing and quarters platform.

A 312-km, 14-in. subsea pipeline connects the Ruby platform with the Senipah terminal on East Kalimantan operated by a subsidiary of Total.

PT Pupuk Kalimantan Timur buys the gas for use in a fertilizer plant.

Mubadala operates the field and holds a 70% working interest in the Sebuku production sharing contract. Total E&P Sebuku and Inpex South Makassar Ltd. hold 15% each.

PROCESSINGQuick Takes

Crosstex to expand Permian gathering, processing

Crosstex Energy LP, Dallas, will expand in the Permian basin by building gas processing and rich-gas gathering capacity. Included will be treating, processing, and gas takeaway; the project will be fully owned by the partnership and supported by long-term, fee-based contracts, Crosstex said.

The $140-million Bearkat processing complex will be installed near the partnership's existing Deadwood joint venture in Glasscock County, Tex. (OGJ Online, July 12, 2011). The plant will have initial capacity of 60 MMcfd, increasing Crosstex's total operated processing capacity in the Permian to about 115 MMcfd. The partnership also will build a 30-mile, high-pressure gathering system upstream of the Bearkat complex to provide additional gathering capacity for producers in Glasscock and Reagan counties.

The entire project is to be completed and operating by mid-2014. Crosstex continues to expand in Howard, Martin, Glasscock, and Reagan counties, the company said.

Citgo crude unit to get partial restart

Citgo Petroleum Corp. said it plans to resume partial crude processing operations at its 167,000-b/d Lemont, Ill., refinery following a fire at the crude distillation unit early last week (OGJ Online, Oct. 24, 2013).

The vacuum distillation unit was the only unit impacted by the Oct. 23 fire, Citgo said. With that unit now isolated from the connecting atmospheric distillation tower, plans are under way to restart the atmospheric section of the crude distillation unit at reduced rates by the end of next week.

There is no information available yet regarding when repairs to the vacuum distillation unit will be completed, the company said.

While Citgo said last week that some downstream units continue to operate in the wake of the fire, identification of those units as well as the refinery's current output remain unavailable.

Big coal-based SNG plant starts in China

Haldor Topsoe AS, Ravnholm, Denmark, reported the start-up in Xinjiang, China, of what it calls the world's largest substitute natural gas plant.

The $4.1 billion, single-train plant has a planned output of 1.4 billion cu m/year of SNG. Qinghua Group of China owns and operates the facility.

The plant uses Haldor Topsoe technology for methanation of synthesis gas derived from coal.

Most of the SNG produced at the Qinghua plant will be moved by pipeline to populous areas of China, especially in the eastern part of the country.

TRANSPORTATIONQuick Takes

Alliance completes Tioga Lateral pipeline

Alliance Pipeline has finished construction on its 80-mile, 12-in. natural gas pipeline in western North Dakota. The project cost $170 million and took a year to complete.

The Tioga Lateral line originates from a Hess Corp. gas processing facility near Tioga, ND, and connects to the Alliance mainline near Sherwood, ND. The line is capable of moving 126 MMcfd of rich natural gas, which is produced in association with oil production in the Williston basin.

Alliance said the line gives operators in Williston access to downstream markets through the Chicago hub, including the Aux Sable NGL fractionation facility. The US Federal Energy Regulatory Commission gave approval for the lateral in October 2012 (OGJ Online, Oct. 1, 2012).

"This state-of-the-art pipeline will help us reduce flaring, add value to our natural resources, and support our nation's energy security," commented North Dakota Gov. Jack Dalrymple.

Based in the US and Canada, the 2,300-mile Alliance Pipeline natural gas transmission system has been in commercial service since 2000 and delivers 1.6 billion bscfd of gas (OGJ Online, Nov. 30, 2000).

Meritage mulls Powder River basin NGL line

A subsidiary of Meritage Midstream Services II LLC, Golden, Colo., has begun a binding open season for a common-carrier pipeline to transport unfractionated natural gas liquids from plants in the Powder River basin.

The 196-mile, 10-in. Thunder Creek NGL Pipeline would connect with the Overland Pass Pipeline near the Colorado-Wyoming border and the Front Range NGL Pipeline near Lucerne, Colo. Design capacity is 40,000 b/d.

Thunder Creek NGL Pipeline LLC will close the open season at 5 p.m. Mountain Time on Nov. 29. It plans to start operations beginning in the second quarter of 2015.

Open season starts for Texas crude line

A subsidiary of Medallion Midstream LLC, Irving, Tex., has begun a binding open season for a crude oil pipeline in Texas between Garden City in Glasscock County and the Colorado City hub in Scurry County, about 60 miles north.

Medallion Pipeline Co. LLC's Wolfcamp Connector would have a capacity of 65,000 b/d.

Medallion said it is considering a southward extension of the Wolfcamp Connector from the Garden City Station about 40 miles into Reagan County, depending on commitments received in the open season. The Reagan County Extension would be able to carry 40,000 b/d of crude to the Garden City Station interconnection with the Wolfcamp Connector.

Target start-ups are the third quarter of 2014 for the Wolfcamp Connector and the fourth quarter of 2014 for the Reagan County Extension. The open season ends at 5 p.m. Central Standard Time on Nov. 27.